What changed in this filing

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Item 1. Business

2026-03-05 compared with 2025-03-11 · 50 added, 124 removed, 432 unchanged (29% of the section changed)

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As of December 31, 2025, we had an interest in 1,446 gross (825 net) producing wells, approximately 930 of which we operate, and 574,599 gross (378,537 net) total acres under lease.

As of December 31, 2024, we had no active drilling rigs.

As of December 31, 2025, we had one active drilling rig.

Total estimated proved reserves as of December 31, 2025, were 69.1 MMBoe.

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PRIMARY BUSINESS OPERATIONS

A comparative discussion of our 2023 to 2022 operating results can be found in Item 1 “Business” included in our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on March 7, 2024.

Our primary operations are the production, development and acquisition of hydrocarbon resources.

The following table presents information concerning our operations as of December 31, 2025.

Weighted Average Economic Reserve Life (Years)(4)

Estimated Proved Reserves (MMBoe) (1) Daily Production (MBoe/d)(2) Reserves/ Production (Years)(3) Weighted Average Economic Reserve Life (Years)(4) Gross Acreage Net Acreage

Geographic Area

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Preparation of Reserves Estimates

Approximately 97.5 percent of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

Approximately 97.9% of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.

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In addition to Mr.

Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee.

Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee (the “Audit Committee”) of the Board of Directors of the Company (the “Board”) .

To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.

The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.

The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, production data, historical price and cost information, property ownership, well logs, geologic maps and well tests.

This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers.

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SandRidge’s reserve engineers and the Reservoir Engineering Manager work closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates.

These independently developed reserve estimates are presented to the Audit Committee of the Board of Directors ("Audit Committee").

These independently developed reserve estimates are presented to the Audit Committee.

In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the

Year Ended December 31,

Cawley, Gillespie & Associates, Inc.

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See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.

Year Ended December 31,

Estimated Proved Reserves (1)

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Standardized Measure of Discounted Net Cash Flows (in millions) (2) $439.6 $362.7

$ 362.7 $ 296.3

PV-10 (in millions) (3) $439.6 $362.7

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All prices are held constant throughout the lives of the properties.

The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below:

Index prices (a) Weighted average

wellhead prices (b)

(per Bbl) Natural gas

(per MMBtu) Oil

(per Bbl) Natural gas

December 31, 2024 $ 75.48 $ 2.13 $ 74.04 $ 19.40 $ 1.02

December 31, 2023 $ 78.22 $ 2.64 $ 76.65 $ 21.53 $ 1.62

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(a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.

These are SEC prices calculated by using trailing 12 month average from the first trading day close of each calendar month.

(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and excludes any impact of derivatives.

(2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes.

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PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities.

The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table

Index prices (a) Weighted average wellhead prices (b)

Oil (per Bbl) Natural gas (per MMBtu) Oil (per Bbl) NGL (per Bbl) Natural gas (per Mcf)

December 31, 2025 $ 65.34 $ 3.39 $ 64.15 $ 17.13 $ 2.07

December 31, 2024 $ 75.48 $ 2.13 $ 74.04 $ 19.40 $ 1.02

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(a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.

These are SEC prices calculated by using trailing 12 month averages from the first trading day close of each calendar month.

(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and exclude any impact of derivatives.

The following table provides a reconciliation of our PV-10 to Standardized Measure:

Year Ended December 31,

(In thousands)

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Standardized Measure of Discounted Net Cash Flows $ 439,568 $ 362,696

Proved Reserves - Mid-Continent .

Proved reserves increased from 55.7 MMBoe at December 31, 2023 to 63.1 MMBoe at December 31, 2024, primarily due to purchases of 16.0 MMBoe, 3.5 MMBoe associated with other commercial improvements, and positive revisions of 2.3 MMBoe related to NGL Yield.

These were partially offset by negative revisions including 6.6 MMBoe due to a decrease in year-end SEC commodity prices for oil and natural gas and price realizations, as well as 6.1 MMBoe from the Company’s production during 2024, and 1.7 MMboe attributable to well performance, well shut-ins and other revisions.

Proved developed Reserves - Proved Developed reserves increased from 55.7 MMBoe at December 31, 2023 to 57.0 MMBoe at December 31, 2024, primarily due to purchases of 9.9 MMBoe, 3.5 MMBoe associated with other commercial improvements.

and positive revisions of 2.3 MMBoe related to NGL Yield.

Proved Undeveloped Reserves - Proved undeveloped reserves increased from 0.0 MMBoe at December 31,2023 to 6.1 MMBoe at December 31, 2024 due to purchases.

Proved Reserves - Proved reserves increased from 63.1 MMBoe at December 31, 2024 to 69.1 MMBoe at December 31, 2025, due to extensions of 7.3 MMBoe, purchases of 1.7 MMBoe, positive net revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations and 4.5 MMBoe associated with other commercial improvements.

These were partially offset by a decrease in SEC oil pricing, 6.8 MMBoe from the Company’s production during 2025, and 3.9 MMBoe attributable to performance, well shut-ins and other revisions.

Proved Developed Reserves - Proved developed reserves increased from 57.0 MMBoe at December 31, 2024 to 60.3 MMBoe at December 31, 2025, primarily due to positive revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations, extensions of 0.8 MMBoe, 4.7 MMBoe of proved undeveloped ("PUD") converted to proved developed ("PDP") reserves in 2025 under our Cherokee play development program and 4.5 MMBoe associated with other commercial improvements.

These were partially offset by negative revisions including 6.8 MMBoe from the Company’s production during 2025, and 3.1 MMBoe attributable to the decrease in SEC oil pricing, well shut-ins and other revisions.

Proved Undeveloped Reserves - Proved undeveloped reserves increased from 6.1 MMBoe at December 31, 2024 to 8.8 MMBoe at December 31, 2025 due to extensions of 6.5 MMBoe and purchases of 1.7 MMBoe.

There were PUD to PDP conversions of 4.7 MMBoe from five operated and four non-operated wells drilled and turned online in 2025.

The company invested $43.7 million to convert these reserves to PDP.

Total increase to proved undeveloped reserves were also partially offset by 0.8 MMBoe attributable to other negative revisions including the decrease in SEC oil pricing.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2025, 2024 and 2023 see “Note 20—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report.

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Drilling Activity

During the year ended December 31, 2025, the Company operated one drilling rig and drilled seven operated wells and completed six wells with one well drilling and another well awaiting completion as of December 31, 2025.

Additionally, four non-operated wells were drilled and completed during 2025.

During the year ended December 31, 2024, there were no operated wells drilled, three operated wells and one non-operated well completed with zero wells awaiting completion at year end 2024.

During the year ended December 31, 2023 there were two operated wells drilled and four wells completed, with zero wells awaiting completion at year end 2023.

Developed and Undeveloped Acreage

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December 31, 2028 5,198 1,857

December 31, 2028 and later — —

Total (1) 23,839 16,499

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We sell our oil, natural gas and NGLs to a variety of customers, including oil and natural gas companies and trading and energy marketing companies.

We had two purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2024.

We had three purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2025.

See “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements in Item 8 of this report for additional information on our major customers.

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For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare.

On December 31, 2020, EPA published its decision to retain the 2015 ozone standards;

however, in October 2021 the Biden Administration announced that was reconsidering this decision under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

On August 21, 2023, the EPA announced a new review of the ozone National Ambient Air Quality Standards and stated that it will incorporate the ongoing reconsideration into this review.

EPA also announced that it will consider the advice and recommendation of the ozone review panel of the Clean Air Scientific Advisory Committee ("CASAC") in its review.

This review is ongoing.

We note that in January 2025, EPA dismissed all of the members of the CASAC and announced it is working to update the committee membership.

On December 31, 2020, the EPA published its decision to retain the 2015 ozone standards;

however, on August 21, 2023, the EPA announced a new review of the ozone National Ambient Air Quality Standards.

Further reductions in the ozone National Ambient Air Quality Standards could affect our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures.

In addition, on December 2, 2023, the EPA announced a final rule under the CAA to reduce methane emissions from the oil and natural gas industry.

In addition, on March 8, 2024, the EPA published a final rule under the CAA to reduce methane emissions from the oil and natural gas industry.

This final rule is discussed in the Climate Change subsection below.

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Such activities are generally prohibited from discharging sediment unless permitted by the EPA or an analogous state agency.

The scope of EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations.

The EPA issued a final rule in September 2015 that attempted to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) under Section 404 of the CWA.

The EPA and the Corps then proposed a rulemaking in June 2017 to repeal the June 2015 WOTUS rule and also announced their intent to issue a new rule redefining the term WOTUS as used in the CWA.

On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule, and EPA and the Corps promulgated the Navigable Waters Protection Rule on April 21, 2020, which provides a revised definition of WOTUS and became effective on June 22, 2020.

These regulations were challenged in federal court, and on August 30, 2021 the U.S.

District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule.

On December 7, 2021, EPA and the Corps issued a proposed rule to again revise the definition of WOTUS.

A year later on December 30, 2022, the agencies announced a final rule called the “Revised Definition of “Waters of the United States’” rule which was published in the Federal Register on January 8, 2023 and took effect on March 20, 2023.

This “Revised Definition of “Waters of the United States’” rule was also challenged in federal court.

On May 25, 2023, the United States Supreme Court issued a decision in the case of Sackett v.

Environmental Protection Agency , which held that parts of the Revised Definition of “Waters of the United States’” rule are invalid.

As a result, the agencies amended key aspects of the rule to conform to the Supreme Court’s decision in Sackett .

This conforming rule called "Revised Definition of 'Waters of the United States';

Conforming," became effective on September 8, 2023.

Nevertheless, due to ongoing litigation over the January 8, 2023 Revised Definition of “Waters of the United States’” rule, the rule is not currently operative in certain states and for certain parties.

EPA and the Corps are implementing the Revised Definition of 'Waters of the United States';

Conforming," in certain states, while in others, the agencies are interpreting “WOTUS” consistent with the pre-2015 regime and the Supreme Court’s decision in Sackett until further notice.

We could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations due to these frequent changes in the regulatory definition of WOTUS and regulatory uncertainty while litigation is pending.

The scope of the EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations.

The EPA issued a proposed rule in November 2025 to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) under Section 404 of the CWA, which is expected to be challenged in litigation once finalized.

We could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations due to frequent changes in the regulatory definition of WOTUS and regulatory uncertainty while litigation is pending.

Moreover, any future changes to regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations.

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Climate Change

In December 2009, the EPA published its findings that emissions of CO 2 , methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.

In December 2009, the EPA published its findings that emissions of CO 2 , methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment (the “Endangerment Finding”) because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

Based on the Endangerment Finding, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Facilities required to obtain PSD permits for their GHG emissions also are required to meet “best available control technology” standards that could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.

In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.

On August 1, 2025, the EPA proposed rescinding the Endangerment Finding.

It remains uncertain how the EPA’s rescindment of the Endangerment Finding, once final, will impact future regulation of GHG emissions.

In June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards in 40 C.F.R.

Part 60, Subpart OOOOa (“Quad Oa”).

On April 18, 2017, the EPA announced its intention to reconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the Quad Oa regulations.

In October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify that meeting certain Quad Oa requirements is technically infeasible.

The EPA proposed further revisions to Quad Oa on September 24, 2019, including rescinding the methane requirements in Quad Oa that apply to sources in the production and processing segments of the industry.

In September 2020, the EPA finalized amendments to Quad Oa that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things.

The Biden Administration undertook a review of the September 2020 rules under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations.

On November 8, 2022, EPA issued a supplemental notice of proposed rulemaking that would impose standards for certain sources that were not addressed in the November 2021 proposal, revise the previously proposed emissions standards, and establish a “super emitter response program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event.”

On December 2, 2023, the EPA announced its final rule under the CAA to reduce methane emissions from the oil and natural gas industry.

The final New Source Performance Standards and Emission Guidelines for Existing Sources for the Crude Oil and Natural Gas Source Category rule was published on March 8, 2024.

On March 8, 2024, the EPA published final New Source Performance Standards and Emission Guidelines for Existing Sources for the Crude Oil and Natural Gas Source Category.

The final rule includes several actions including finalizing revisions to the New Source Performance Standards in 40 C.F.R Part 60, Subpart OOOOb regulating GHGs (in the form of methane) and volatile organic compound emissions from new, modified and existing sources within the Crude Oil and Natural Gas source category, including sources located in the production, processing, and transmission and storage segments;

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Part 60, Subpart OOOOc for states to follow in developing and implementing state plans to establish performance standards to limit methane emissions from existing sources;

finalizing actions stemming from the joint resolution of Congress, adopted on June 30, 2021 discussed above, including creating the proposed "super emitter program”;

establishing a "super emitter program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event”;

and finalizing a protocol under 40 C.F.R.

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The Company does not currently conduct routine flaring.

After the rule was issued, EPA issued an interim final rule effective in August 2024 to make technical, non-substantive corrections to the rule.

In addition, in May 2024, EPA granted industry petitioners’ request for reconsideration on two aspects of the rule related to monitoring and emergency operations for flares.

On December 20, 2024, EPA proposed discrete technical revisions to these two provisions.

The proposed revisions were published to the Federal Register on January 15, 2025.

The proposed amendments only address petitions for reconsideration and do not propose changes to other aspects of the final rule.

This rule and any future revisions thereto will continue to require oil and gas operators to expend material sums.

Furthermore, on January 12, 2024, EPA announced a proposed rulemaking to reduce methane emissions from the oil and gas sector pursuant to the Inflation Reduction Act.

The rule was finalized on November 12, 2024.

The rule assesses a charge called a Waste Emissions Charge on larger emitters of waste methane if their emissions exceed specific performance levels set by Congress in the Inflation Reduction Act.

Specifically, the Inflation Reduction Act provides that the Waste Emissions Charge applies to methane from certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the Greenhouse Gas Reporting Program, beginning with methane emissions reported in calendar year 2024.

Also, as directed by Congress, the Waste Emissions Charge starts at $900 per metric ton of wasteful emissions in CY 2024, increasing to $1,200 for CY 2025, and $1,500 for CY 2026 and beyond, and only applies to emissions that exceed statutorily specified methane intensity levels.

On February 4, 2025, members of the U.S.

House and Senate introduced a joint resolution pursuant to the Congressional Review Act seeking to overturn the EPA’s November 2024 rule implementing the Waste Emissions Charge.

Given the EPA rule was finalized within the last 60 working days of the previous Congress, it may be modified or repealed under the Congressional Review Act with a simple majority vote in the House and Senate and approval by the President.

Accordingly, the EPA rulemaking implementing the Waste Emissions Charge could be overturned.

However, the Congressional Review Act does not provide a means to rescind the Waste Emissions Charge Congressional mandate that was passed as part of the Inflation Reduction Act.

If Congress is not successful in repealing the Waste Emissions Charge, then it could result in an increased expense to the Company, which could begin in 2025.

In addition, in November 2016, the U.S.

On November 26, 2025, the EPA issued a final rule to extend several compliance deadlines in the March 2024 final rule under Subparts OOOOb/c.

Furthermore, the Inflation Reduction Act established a Waste Emissions Charge that applies to methane from certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the EPA's Greenhouse Gas Reporting Program.

The One Big Beautiful Bill Act, signed by President Trump on July 4, 2025, delays the imposition of the methane emissions charge until calendar year 2034.

In addition, in March 2024, the U.S.

Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the EPA Quad Oa requirements.

However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities.

Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018.

Both the 2016 and the 2018 rule were challenged in federal court.

On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule.

As a result of these decisions, the 1979 regulations concerning venting, flaring and lost production on federal land have been reinstated.

On November 28, 2022, the BLM announced a new proposed rule regulating emissions of methane in connection with the production of oil and gas on federal and Tribal lands.

The final Methane Waste Prevention Rule was issued in March 2024 and became effective on June 10, 2024.

The final Methane Waste Prevention Rule requires operators to use all reasonable precautions to prevent waste, mandates that either a Self-Certification Statement or a Waste Minimization Plan to be submitted with the Application for Permit to Drill, imposes limits related to flaring, and requires LDAR plans, among other provisions.

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In September 2024, the United States District Court for the District of North Dakota granted the plaintiff states’ motion for preliminary injunction, thereby prohibiting BLM from enforcing the Methane Waste Prevention Rule against the plaintiff states pending the outcome of the litigation.

In November 2025, BLM announced that it will delay enforcement of certain compliance deadlines in the Methane Waste Prevention Rule that were to take effect in December 2025.

Notably, several states where we operate have adopted similar rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions.

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On an international level, the United States agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”).

However, the Paris Agreement does not impose any binding obligations on the United States.

In June 2017, the United States announced it would withdraw from the Paris Agreement, which became effective November 4, 2020.

The United States later rejoined the Paris Agreement as of February 19, 2021.

However, on January 20, 2025, President Trump issued an executive order entitled Putting America First In International Environmental Agreements.

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Although some states and local governments remain committed to the principles of the Paris Agreement, the executive order could serve as a catalyst for potential agency action relevant to our business.

At the 26th Conference of the Parties to the United Nations Framework Convention of Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union launched the Global Methane Pledge, an initiative to reduce global methane emissions by at least 30% from 2020 levels by 2030.

At COP27 in Sharm El-Sheik in November 2022, the Biden Administration unveiled an updated U.S.

Methane Emissions Reduction Action Plan, building upon the first plan released at COP26.

At COP28, the Biden Administration announced the new technology standards pursuant to the CAA for reduced methane emissions, as discussed above in this disclosure.

Most recently, at COP29, governments including the U.S.

and philanthropies announced nearly $500 million in new grant funding in 2024 for methane abatement.

Finally, in November 2024, the Biden Administration released its Updated Methane Emissions Reduction Action Plan, describing actions taken since December 2023 to address U.S.

methane emissions.

The Putting America First In International Environmental Agreements executive order is likely to impact these actions, though the full impact of the executive order remains uncertain at this time.

In addition to ordering the United States’ withdrawal as described above, the executive order directs the United States Ambassador to the United Nations, the Secretary of State, and the Secretary of the Treasury to cease or revoke any financial commitment made by the United States under the United Nations Framework Convention on Climate Change.

It is not possible at this time to predict how or if the United States or states might impose further restrictions on GHGs.

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The EPA also issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act (“TSCA”) in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing but, to date, has taken no further action.

Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

District Court of Wyoming struck down this rule in June 2016.

The June 2016 decision was appealed by the BLM to the U.S.

Circuit Court of Appeals for the Tenth Circuit.

However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule.

In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking.

The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain.

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Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

In addition to asserting regulatory authority, certain government agencies have conducted reviews focusing on environmental issues associated with hydraulic fracturing practices.

For example, the EPA released its final report, Hydraulic Fracturing for Oil and Gas:

Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States , regarding the potential impacts of hydraulic fracturing on drinking water resources in December 2016.

The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water sources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:

water withdrawals for fracturing in times or areas of low water availability;

surface spills during the management of fracturing fluids, chemicals or produced water;

injection of fracturing fluids into wells with inadequate mechanical integrity;

injection of fracturing fluids directly into groundwater resources;

discharge of inadequately treated fracturing wastewater to surface waters;

and disposal or storage of fracturing wastewater in unlined pits.

Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

We diligently review best practices and industry standards and comply with all regulatory requirements in the protection of potable water sources.

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In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties.

Pooling orders can alter the timing and manner of development.

Regulatory changes to pooling standards could further increase the difficulty, cost or timing of obtaining pooling orders and could impede development plans.

In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.

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State agencies in Kansas, Oklahoma, and Texas impose financial assurance requirements on operators.

The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

The Corps and many other state and local authorities also have regulations for plugging and abandonment (including regulations that may arise out of Oklahoma's Senate Bill 131), decommissioning and site restoration.

Natural Gas Sales and Transportation

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business